Edgar Filing: UNITIL CORP

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

QUARTERLY REPORT UNDER SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For Quarter Ended June 30, 2008

Commission File Number 1-8858

UNITIL CORPORATION

(Exact name of registrant as specified in its charter)

New Hampshire

02-0381573

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)


6 Liberty Lane West, Hampton, New Hampshire		03842-1720
(Address of principal executive office)		(Zip Code)

Registrant’s telephone number, including area code: (603) 772-0775

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.


Large Accelerated filer ¨		Accelerated filer x

Non-accelerated filer ¨		Smaller reporting company ¨
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes¨ No x

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.


Class		Outstanding at August 6, 2008
Common Stock, No par value		5,774,402 Shares

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

FORM 10-Q

For the Quarter Ended June 30, 2008

Table of Contents


			Page No.
Part I. Financial Information

	Item 1.	Financial Statements

		Consolidated Statements of Earnings - Three and Six Months Ended June 30, 2008 and 2007	16

		Consolidated Balance Sheets, June 30, 2008, June 30, 2007 and December 31, 2007	17-18

		Consolidated Statements of Cash Flows - Six Months Ended June 30, 2008 and 2007	19

		Notes to Consolidated Financial Statements	20-29

	Item 2.	Management’s Discussion and Analysis (MD&A) of Financial Condition and Results of Operations	2-15

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	29

	Item 4.	Controls and Procedures	29

	Item 4T.	Controls and Procedures	Inapplicable

Part II. Other Information

	Item 1.	Legal Proceedings	29

	Item 1A.	Risk Factors	29

	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	29

	Item 3.	Defaults Upon Senior Securities	Inapplicable

	Item 4.	Submission of Matters to a Vote of Security Holders	Inapplicable

	Item 5.	Other Information	Inapplicable

	Item 6.	Exhibits	31

Signatures			32

Exhibit 11		Computation of Earnings per Weighted Average Common Share Outstanding

PART I. FINANCIAL INFORMATION

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

OVERVIEW

Unitil Corporation (Unitil or the Company) is a public utility holding company. Unitil’s principal business is the retail distribution of electricity and natural gas through two utility subsidiaries: Unitil Energy System’s Inc. (UES) and Fitchburg Gas and Electric Light Company (FG&E). UES is an electric utility with an operating franchise in the southeastern seacoast and capital city areas of New Hampshire. FG&E is a combination gas and electric utility with an operating franchise in the greater Fitchburg area of north central Massachusetts.

Unitil’s two retail distribution utilities serve approximately 99,400 electric customers and 15,000 natural gas customers in their franchise areas. The retail distribution companies are pure distribution utilities with a combined investment in net utility plant of $251.1 million at June 30, 2008. Substantially all of Unitil’s revenue and earnings are derived from regulated utility operations.

Unitil also conducts non-regulated operations principally through its Usource™ (Usource) subsidiary. Usource provides energy brokering and consulting services to large commercial and industrial customers in the northeastern United States. Unitil’s other subsidiaries include Unitil Service and Unitil Realty, which provide centralized facilities, management and administrative services to Unitil’s affiliated companies. Unitil’s consolidated net income includes the earnings of the holding company and these subsidiaries.

On February 15, 2008, the Company entered into a Stock Purchase Agreement (Agreement) with NiSource Inc. (NiSource) and Bay Sate Gas Company (Bay State, which is a wholly owned utility subsidiary of NiSource), to acquire all of the outstanding stock of Northern Utilities, Inc. (Northern), and Granite State Gas Transmission, Inc. (Granite) for $160 million in cash, which amount is subject to a working capital adjustment. The transaction is expected to be financed by newly issued common stock and debt.

Northern’s principal business is the retail distribution of natural gas to approximately 53,000 customers located in 44 coastal New Hampshire and southern Maine communities. Portions of Northern’s natural gas service territory are contiguous and overlapping with Unitil’s electric distribution service territory in New Hampshire. Granite’s principal business is a natural gas transmission company, principally engaged in the business of providing natural gas transportation services to Northern for its access to natural gas pipeline supplies.

Consummation of the acquisition is subject to various closing conditions, including but not limited to the receipt of requisite regulatory approvals from certain federal and state public utility, antitrust and other regulatory authorities. It is currently anticipated that the acquisition will be consummated in the fourth quarter of 2008. However, no assurance can be given that the acquisition will occur, or, the timing of its completion.

RATES AND REGULATION

Unitil’s utility operations related to wholesale and interstate business activities are regulated by the Federal Energy Regulatory Commission (FERC). The retail distribution utilities, UES and FG&E, are subject to regulation by the New Hampshire Public Utilities Commission (NHPUC) and the Massachusetts Department of Public Utilities (MDPU), formerly the Massachusetts Department of Telecommunications and Energy, respectively, in regards to their rates, issuance of securities and other accounting and operational matters. Because Unitil’s primary operations are subject to rate regulation, the regulatory treatment of various matters could significantly affect the Company’s operations and financial position.

Unitil’s retail distribution utilities have the franchise to deliver electricity and/or natural gas to all customers in their franchise areas, at rates established under traditional cost of service regulation. Under this regulatory structure, UES and FG&E recover the cost of providing distribution service to their customers based on a historical test year, in addition to earning a return on their capital investment in utility assets.

As a result of the implementation of retail choice in New Hampshire and Massachusetts, Unitil’s customers are free to contract for their supply of electricity with third-party suppliers. The retail distribution utilities provide for the delivery of that supply of electricity over their distribution systems at regulated rates. Both UES and FG&E continue to provide basic or default electric supply service to those customers who do not obtain their supply from third-party suppliers, with the costs associated with electricity supplied by the Company being recovered on a pass-through basis under periodically-adjusted rates.

As a result of the introduction of retail choice for all natural gas customers in Massachusetts, FG&E’s customers are free to contract for their supply of natural gas with third-party suppliers. FG&E continues to provide natural gas supply services to those customers who do not obtain their supply from third-party suppliers. The costs associated with natural gas supplied by FG&E are recovered on a pass-through basis under periodically adjusted rates.

CAUTIONARY STATEMENT

This report and the documents we incorporate by reference into this report contain statements that constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, Section 21E of the Securities Exchange Act of 1934 and the Private Securities Litigation Reform Act of 1995. All statements, other than statements of historical fact, included or incorporated by reference into this report, including, without limitation, statements regarding the financial position, business strategy and other plans and objectives for the Company’s future operations, are forward-looking statements.

These statements include declarations regarding the Company’s beliefs and current expectations. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “should,” “expects,” “plans,” “anticipates,” “believes,” “estimates,” “predicts,” “potential” or “continue” or the negative of such terms or other comparable terminology. These forward-looking statements are subject to inherent risks and uncertainties in predicting future results and conditions that could cause the actual results to differ materially from those projected in these forward-looking statements. Some, but not all, of the risks and uncertainties include the following:

•

Variations in weather;

•

Changes in the regulatory environment;

•

Customers’ preferences on energy sources;

•

Interest rate fluctuation and credit market concerns;

•

General economic conditions;

•

Fluctuations in supply, demand, transmission capacity and prices for energy commodities;

•

Increased competition; and

•

Customers’ future performance under multi-year energy brokering contracts.

•

Risks associated with the acquisition of Northern and Granite, discussed above include:

•

Successful integration of the acquired business into the Company;

•

Receipt of regulatory approval of the transaction;

•

Ability to finance transaction at reasonable terms; and

•

Acquisition costs expended for banker fees, legal fees and other acquisition related expenses would adversely affect the Company’s financial condition if the acquisition is not completed;

Many of these risks are beyond the Company’s control. Any forward-looking statements speak only as of the date of this report, and the Company undertakes no obligation to update any forward-looking statements to reflect events or circumstances after the date on which such statements are made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for the Company to predict all of these factors, nor can the Company assess the impact of any such factor on its business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements. There have been no material changes to the risk factors disclosed in the Company’s Form 10-K for the year-ended December 31, 2007 as filed with the Securities and Exchange Commission on February 12, 2008, other than the risks disclosed above associated with the acquisition of Northern and Granite.

RESULTS OF OPERATIONS

The following section of MD&A compares the results of operations for each of the two fiscal periods ended June 30, 2008 and June 30, 2007 and should be read in conjunction with the accompanying Consolidated Financial Statements and the accompanying Notes to Consolidated Financial Statements included in Item 1 of this report.

Earnings Overview

The Company’s Earnings Applicable to Common Shareholders (Net Income) was $1.6 million for the second quarter of 2008, compared to net income of $1.7 million for the second quarter of 2007. Earnings per common share (EPS) were $0.28 for the three months ended June 30, 2008 compared with $0.30 in the second quarter of 2007. Earnings for the second quarter of 2008 reflect higher gas utility sales margins and lower interest expense offset by higher operating expenses and depreciation in the quarter. For the six months ended June 30, EPS were $0.85 for 2008 compared to $0.76 for 2007, an increase of $0.09 per share, or 12%.

The following table presents the significant items (discussed below) contributing to the change in earnings per share in the three and six month periods ended June 30, 2008:


2008 Earnings Per Share vs. 2007
		Period Ended June 30,
		QTD			YTD
	2007	$	0.30		$	0.76
Electric Sales Margin			—			(0.04	)
Gas Sales Margin			0.02			0.12
Usource Sales Margin			(0.01	)		—
Operation & Maintenance Expense			(0.02	)		0.17
Depreciation, Amortization & Other			(0.02	)		(0.12	)
Interest Expense, Net			0.01			(0.04	)

	2008	$	0.28		$	0.85

Unitil’s total electric kilowatt (kWh) sales decreased 3.1% and 2.2% in the three and six month periods ended June 30, 2008, respectively compared to the same periods in 2007. Natural gas sales in the three and six month periods ended June 30, 2008 decreased 4.6% and 2.2%, respectively, compared to the same periods in 2007. The lower unit sales in 2008 compared to 2007 reflect a milder winter heating season this year and lower average usage by our customers reflecting a slowing economy and energy conservation.

Electric sales margin was flat in the three month period ended June 30, 2008 compared to the same period in 2007. For the six month period ended June 30, 2008, electric sales margin decreased $0.4 million compared to the same period in 2007. The decrease in electric sales margin primarily reflects lower sales volumes, which was partially offset by higher electric base rates, implemented in March of 2008.

Natural gas sales margin increased $0.2 million and $1.1 million in the three and six months ended June 30, 2008, respectively, compared to the same periods in 2007 primarily reflecting higher gas base rates, implemented in November of 2007, partially offset by lower sales volumes.

Usource revenues decreased by $0.1 million in the three month period ended June 30, 2008 compared to the same period in 2007 and were flat in the six month period ended June 30, 2008 compared to the same period in 2007.

Total O&M expenses increased $0.2 million for the three month period ended June 30, 2008 compared to the same period in 2007. The increase in the three month period reflects higher salary and benefit costs of $0.4 million and higher bad debt expense of $0.1 million partially offset by lower utility operating costs of $0.1 million

and lower professional fees and all other expenses of $0.2 million. For the six month period ended June 30, 2008, O&M expenses decreased $1.6 million compared to the same period in 2007, including a reduction of $2.8 million from the proceeds of an insurance settlement and lower other utility operating costs of $0.3 million, partially offset by increases in salary and benefit costs of $1.1 million, higher bad debt expenses of $0.2 million and all other expenses, net of $0.2 million.

Depreciation, Amortization, Taxes & Other expenses increased $0.1 million and $1.3 million in the three and six month periods ended June 30, 2008 compared to the same periods in 2007, primarily reflecting the amortization, in the first quarter of 2008, of $0.7 million of natural gas inventory carrying costs deferred under a previous regulatory ruling and higher depreciation on normal utility plant additions.

Also in the second quarter, the Unitil Corporation Board of Directors declared the regular quarterly dividend on the Company’s common stock of $0.345 per share. This quarterly dividend results in a current effective annual dividend rate of $1.38 per share representing an unbroken record of quarterly dividend payments since trading began in Unitil’s common stock.

A more detailed discussion of the Company’s results of operations for the three and six months ended June 30, 2008 and a period-to-period comparison of changes in financial position are presented below.

Balance Sheet

The Company’s investment in Net Utility Plant increased by $7.3 million as of June 30, 2008 compared to June 30, 2007. This increase was due to capital expenditures related to UES’ and FG&E’s electric and gas distribution systems, including expenditures of approximately $1.2 million for the Company’s Advanced Metering Infrastructure (AMI) project.

Regulatory Assets decreased $31.1 million as of June 30, 2008 compared to June 30, 2007, primarily reflecting current year cost recoveries. A significant portion of this decrease is matched by a corresponding decrease of $19.9 million in Power Supply Contract Obligations. The remaining decrease primarily reflects lower levels of Regulatory Assets associated with deferred taxes and retirement benefit obligations as well as recoveries of deferred charges.

Electric Sales, Revenues and Margin

Kilowatt-hour Sales – Unitil’s total electric kilowatt (kWh) sales decreased 3.1% and 2.2% in the three and six month periods ended June 30, 2008, respectively compared to the same periods in 2007. Electric kWh sales to residential customers in the three and six month periods ended June 30, 2008 decreased 3.0% and 1.8%, respectively, compared to the same periods in 2007 while sales to C&I customers decreased 3.2% and 2.5%, respectively, in those periods compared to the same periods in 2007. The lower kWh sales in 2008 compared to 2007 were primarily driven by lower average usage by our customers reflecting a slowing economy and energy conservation.

The following table details total kWh sales for the three and six months ended June 30, 2008 and 2007 by major customer class:


kWh Sales (millions)
	Three Months Ended June 30,						Six Months Ended June 30,
	2008	2007	Change		% Change		2008	2007	Change		% Change
Residential	147.5	152.0	(4.5	)	(3.0	%)	329.9	335.9	(6.0	)	(1.8	%)
Commercial / Industrial	254.0	262.5	(8.5	)	(3.2	%)	515.1	528.2	(13.1	)	(2.5	%)

Total	401.5	414.5	(13.0	)	(3.1	%)	845.0	864.1	(19.1	)	(2.2	%)

Electric Operating Revenues and Sales Margin – The following table details total Electric Operating Revenues and Sales Margin for the three and six month periods ended June 30, 2008 and 2007:


Electric Operating Revenues and Sales Margin (millions)
	Three Months Ended June 30,									Six Months Ended June 30,
	2008		2007		$ Change			% Change⁽¹⁾		2008		2007		$ Change			% Change⁽¹⁾
Electric Operating Revenue:
Residential	$	25.9	$	25.9	$	—		—		$	56.2	$	58.6	$	(2.4	)	(2.1	%)
Commercial / Industrial		26.1		25.8		0.3		0.6	%		52.4		55.8		(3.4	)	(3.0	%)

Total Electric Operating Revenue	$	52.0	$	51.7	$	0.3		0.6	%	$	108.6	$	114.4	$	(5.8	)	(5.1	%)

Cost of Electric Sales:
Purchased Electricity	$	36.8	$	36.3	$	0.5		1.0	%	$	79.7	$	84.5	$	(4.8	)	(4.3	%)
Conservation & Load Management		0.8		1.0		(0.2	)	(0.4	%)		1.4		2.0		(0.6	)	(0.5	%)

Electric Sales Margin	$	14.4	$	14.4	$	—		—		$	27.5	$	27.9	$	(0.4	)	(0.3	%)

⁽¹⁾	Represents change as a percent of Total Electric Operating Revenue.

Total Electric Operating Revenues, increased by $0.3 million, or 0.6%, and decreased by $5.8 million, or 5.1%, in the three and six month periods ended June 30, 2008, respectively, compared to the same periods in 2007. Total Electric Operating Revenues include the recovery of costs of electric sales, which are recorded as Purchased Electricity and Conservation & Load Management (C&LM) in Operating Expenses. The net increase in Total Electric Operating Revenues in the three month period reflects higher Purchased Electricity costs of $0.5 million partially offset by lower C&LM revenues of $0.2 million. The net decrease in Total Electric Operating Revenues in the six month period reflects lower Purchased Electricity costs of $4.8 million, lower C&LM revenues of $0.6 million and lower sales margin of $0.4 million.

Purchased Electricity and C&LM revenues increased a net $0.3 million, or 0.6%, and decreased $5.4 million, or 4.8%, of Total Electric Operating Revenues in the three and six month periods ended June 30, 2008, respectively, compared to the same periods in 2007. The increase in the three month period primarily reflects higher electric commodity prices, partially offset by lower sales volumes. The decrease in the six month period reflects lower sales volumes, an increase in the amount of electricity purchased by customers directly from third-party suppliers and lower spending on energy efficiency and conservation programs. Purchased Electricity revenues include the recovery of the cost of electric supply as well as other energy supply related restructuring costs, including long-term power supply contract buyout costs. C&LM revenues include the recovery of the cost of energy efficiency

and conservation programs. The Company recovers the cost of Purchased Electricity and C&LM in its rates at cost on a pass through basis.

Electric sales margin was flat in the three month period ended June 30, 2008 compared to the same period in 2007. For the six month period ended June 30, 2008, electric sales margin decreased $0.4 million compared to the same period in 2007. The decrease in electric sales margin primarily reflects lower sales volumes, partially offset by higher electric base rates, implemented in March of 2008.

Gas Sales, Revenues and Margin

Therm Sales – Unitil’s total therm sales of natural gas in the three and six month periods ended June 30, 2008 decreased 4.6% and 2.2%, respectively, compared to the same periods in 2007. Gas sales to residential customers in the three and six month periods ended June 30, 2008 decreased 8.7% and 4.2%, respectively, compared to the same periods in 2007 while sales to C&I customers decreased 2.4% and 0.9%, respectively, in those periods compared to the same periods in 2007. The decrease in gas sales in 2008 reflects a milder winter heating season this year and lower average usage by our customers reflecting a slowing economy and energy conservation.

The following table details total firm therm sales for the three and six months ended June 30, 2008 and 2007, by major customer class:


Therm Sales (millions)
	Three Months Ended June 30,						Six Months Ended June 30,
	2008	2007	Change		% Change		2008	2007	Change		% Change
Residential	2.1	2.3	(0.2	)	(8.7	%)	6.9	7.2	(0.3	)	(4.2	%)
Commercial / Industrial	4.1	4.2	(0.1	)	(2.4	%)	10.9	11.0	(0.1	)	(0.9	%)

Total	6.2	6.5	(0.3	)	(4.6	%)	17.8	18.2	(0.4	)	(2.2	%)

Gas Operating Revenues and Sales Margin – The following table details total Gas Operating Revenues and Sales Margin for the three and six months ended June 30, 2008 and 2007:


Gas Operating Revenues and Sales Margin (millions)
	Three Months Ended June 30,									Six Months Ended June 30,
	2008		2007		$ Change			% Change⁽¹⁾		2008		2007		$ Change			% Change⁽¹⁾
Gas Operating Revenue:
Residential	$	3.5	$	3.6	$	(0.1	)	(1.6	%)	$	11.6	$	11.7	$	(0.1	)	(0.4	%)
Commercial / Industrial		3.1		2.8		0.3		4.7	%		9.3		8.9		0.4		1.9	%

Total Gas Operating Revenue	$	6.6	$	6.4	$	0.2		3.1	%	$	20.9	$	20.6	$	0.3		1.5	%

Cost of Gas Sales:
Purchased Gas	$	3.9	$	3.9	$	—		—		$	12.9	$	13.7	$	(0.8	)	(3.8	%)
Conservation & Load Management		0.1		0.1		—		—			0.1		0.1		—		—

Gas Sales Margin	$	2.6	$	2.4	$	0.2		3.1	%	$	7.9	$	6.8	$	1.1		5.3	%

⁽¹⁾	Represents change as a percent of Total Gas Operating Revenue.

Total Gas Operating Revenues increased $0.2 million, or 3.1%, and $0.3 million, or 1.5%, in the three and six month periods ended June 30, 2008, respectively, compared to the same periods in 2007. Total Gas Operating Revenues include the recovery of the cost of sales, which are recorded as Purchased Gas and C&LM in Operating Expenses. The net increase in Total Gas Operating Revenues in the three month period reflects higher sales margin of $0.2 million. The net increase in Total Gas Operating Revenues in the six month period reflects higher sales margin of $1.1 million, partially offset by lower Purchased Gas costs of $0.8 million.

Purchased Gas and C&LM revenues were flat in the three month period ended June 30, 2008 compared to the same period in 2007 and decreased $0.8 million, or 3.8% of Total Gas Operating Revenues in the six month period ended June 30, 2008 compared to the same period in 2007. The decrease in the six month period reflects lower sales volumes and an increase in the amount of natural gas purchased by customers directly from third-party suppliers, partially offset by higher natural gas commodity prices. Purchased Gas revenues include the recovery of the cost of gas supply as well as the other energy supply related costs. C&LM revenues include the recovery of the cost of energy efficiency and conservation programs. The Company recovers the cost of Purchased Gas and C&LM in its rates at cost on a pass through basis.

Operating Revenue - Other

The following table details total Other Revenue for the three and six months ended June 30, 2008 and 2007:


Other Revenue (000’s)
	Three Months Ended June 30,									Six Months Ended June 30,
	2008		2007		$ Change			% Change		2008		2007		$ Change	% Change
Other	$	0.8	$	0.9	$	(0.1	)	(11.1	%)	$	1.8	$	1.8	—	—

Total Other Revenue	$	0.8	$	0.9	$	(0.1	)	(11.1	%)	$	1.8	$	1.8	—	—

Total Other Revenue decreased $0.1 million, or 11.1% in the three month period ended June 30, 2008 compared to the same period in 2007. The decrease reflects lower revenues from the Company’s non-regulated energy brokering business, Usource. Total Other Revenues for the six month period ended June 30, 2008 were flat compared to the same period in 2007.

Operating Expenses

Purchased Electricity – Purchased Electricity expenses include the cost of electric supply as well as other energy supply related restructuring costs, including long-term power supply contract buyout costs. Purchased Electricity increased $0.5 million, or 1.4%, and decreased $4.8 million, or 5.7%, in the three and six month periods ended June 30, 2008, respectively, compared to the same periods in 2007. The increase in the three month period primarily reflects higher electric commodity prices, partially offset by lower sales volumes. The decrease in the six month period reflects lower sales volumes, an increase in the amount of electricity purchased by customers directly from third-party suppliers and lower spending on energy efficiency and conservation programs. The Company recovers the costs of Purchased Electricity in its rates at cost on a pass through basis and therefore changes in these expenses do not affect Net Income.

Purchased Gas – Purchased Gas expenses include the cost of gas purchased and manufactured to supply the Company’s total gas supply requirements. Purchased Gas expenses were flat in the three month period ended June 30, 2008 compared to the same period in 2007 and decreased $0.8 million, or 5.8% in the six month period ended June 30, 2008 compared to the same period in 2007. The decrease in the six month period reflects lower

sales volumes and an increase in the amount of natural gas purchased by customers directly from third-party suppliers, partially offset by higher natural gas commodity prices. The Company recovers the costs of Purchased Gas in its rates at cost on a pass through basis and therefore changes in these expenses do not affect Net Income.

Operation and Maintenance (O&M) – O&M expense includes electric and gas utility operating costs, and the operating cost of the Company’s unregulated business activities. Total O&M expenses increased $0.2 million for the three month period ended June 30, 2008 compared to the same period in 2007. The increase in the three month period reflects higher salary and benefit costs of $0.4 million and higher bad debt expense of $0.1 million partially offset by lower utility operating costs of $0.1 million and lower professional fees and all other expenses of $0.2 million. For the six month period ended June 30, 2008, O&M expenses decreased $1.6 million compared to the same period in 2007, including a reduction of $2.8 million from the proceeds of an insurance settlement and lower other utility operating costs of $0.3 million, partially offset by increases in salary and benefit costs of $1.1 million, higher bad debt expenses of $0.2 million and all other expenses, net of $0.2 million.

Conservation & Load Management – C&LM expenses are associated with the development, management, and delivery of the Company’s Energy Efficiency programs. Energy Efficiency programs are designed, in conformity with state regulatory requirements, to help consumers use natural gas and electricity more efficiently and thereby decrease their energy costs. Programs are tailored to residential, small business and large business customer groups and provide educational materials, technical assistance, and rebates that contribute toward the cost of purchasing and installing approved measures. Approximately 90% of these costs are related to electric operations and 10% to gas operations.

Total C&LM expenses decreased $0.2 million, or 18.2% and $0.6 million, or 28.6%, in the three and six month periods ended June 30, 2008 compared to the same periods in 2007. These changes reflect the timing of spending on the implementation of Energy Efficiency programs. These costs are collected from customers on a pass through basis and therefore, fluctuations in program costs have no impact on Net Income.

Depreciation, Amortization and Taxes

Depreciation and Amortization – Depreciation and Amortization expense increased by $0.1 million, or 2.3% and $0.8 million, or 9.0% in the three and six month periods ended June 30, 2008, respectively, compared to the same periods in 2007. The increase in the three month period primarily reflects higher depreciation on normal utility plant additions, partially offset by lower amortization on computer systems. The increase in the six month period primarily reflects the amortization, in the first quarter of 2008, of $0.7 million of natural gas inventory carrying costs deferred under a previous regulatory ruling and higher depreciation on normal utility plant additions.

Local Property and Other Taxes – Local Property and Other Taxes in the three month period ended June 30, 2008 were flat compared to the same period in 2007 and increased by $0.2 million, or 6.9% in the six month period ended June 30, 2008 compared to the same period in 2007. This increase was due to higher property tax rates on increased property assessments and higher payroll taxes on higher compensation expenses.

Federal and State Income Taxes – Federal and State Income Taxes were lower by $0.1 million in the three month period ended June 30, 2008 compared to the same period in 2007 reflecting lower pre-tax earnings. Federal and State Income Taxes were higher by $0.1 million in the six month period ended June 30, 2008 compared to the same period in 2007 reflecting higher pre-tax earnings.

Other Non-operating Expenses (Income)

Other Non-operating Expenses (Income) increased by less than $0.1 million and by $0.2 million in the three and six month periods ended June 30, 2008 compared to the same periods in 2007. The increase in the six month period reflects an adjustment of $0.1 million in conjunction with the Company’s recently approved electric base distribution rate increase in Massachusetts.

Interest Expense, Net

Interest expense is presented in the financial statements net of interest income. Interest expense is mainly comprised of interest on long-term debt and short-term borrowings. Certain reconciling rate mechanisms used by the Company’s distribution operating utilities give rise to regulatory assets (and regulatory liabilities) on which interest is calculated.

The Company operates a number of reconciling rate mechanisms to recover specifically identified costs on a pass through basis. These reconciling rate mechanisms track costs and revenue on a monthly basis. In any given month, this monthly tracking and reconciling process will produce either an under-collected or an over-collected balance of costs. In accordance with the Company’s tariff, interest is accrued on these balances and will produce either interest income or interest expense. Interest income is recorded on an under-collection of costs, which creates a regulatory asset to be recovered in future periods when rates are reset. Interest expense is recorded on an over-collection of costs, which creates a regulatory liability to be refunded in future periods when rates are reset.


Interest Expense, Net (Millions)	Three Months Ended June 30,									Six Months Ended June 30,
	2008			2007			Change			2008			2007			Change
Interest Expense
Long-term Debt	$	2.9		$	2.8		$	0.1		$	5.7		$	5.3		$	0.4
Short-term Debt		0.1			0.3			(0.2	)		0.4			0.7			(0.3	)
Regulatory Liabilities		—			0.2			(0.2	)		0.1			0.3			(0.2	)

Subtotal Interest Expense		3.0			3.3			(0.3	)		6.2			6.3			(0.1	)

Interest Income
Regulatory Assets		(0.6	)		(0.7	)		0.1			(1.3	)		(1.5	)		0.2
AFUDC and Other		(0.1	)		(0.2	)		0.1			—			(0.3	)		0.3

Subtotal Interest Income		(0.7	)		(0.9	)		0.2			(1.3	)		(1.8	)		0.5

Total Interest Expense, Net	$	2.3		$	2.4		$	(0.1	)	$	4.9		$	4.5		$	0.4

Interest Expense, Net decreased $0.1 million for the three month period ended June 30, 2008 compared to the same period in 2007. The decrease in the three month period reflects lower short term interest expense. For the six month period ended June 30, 2008, Interest Expense, Net increased $0.4 million compared to the same period in 2007, reflecting higher overall debt outstanding. Interest expense on long-term borrowings increased in both the three and six month periods in 2008 compared to 2007 due to the issuance of new fixed rate long-term debt. On May 2, 2007, Unitil Corporation issued and sold $20 million of 6.33% Senior Long-Term Notes, due May 1, 2022, to institutional investors in the form of a private placement. The Company utilized the proceeds from the long-term Note financing to refinance existing short-term debt and for other corporate purposes of the Company’s principal utility subsidiaries. The resulting reduction in average daily short-term bank borrowings lowered short-term debt interest expense in both the three and six month periods in 2008 compared to 2007. An adjustment of $0.2 million in the first quarter of 2008 related to earnings on funds used for capital projects ordered in conjunction with the Company’s recently approved electric base distribution rate increase in Massachusetts and lower carrying charges earned on regulatory assets, which are adjusted periodically to reflect prevailing interest rates, also contributed to the increase in Interest Expense, Net in the six month period ended June 30, 2008 compared to the same period in 2007.

CAPITAL REQUIREMENTS

Sources of Capital

Unitil requires capital to fund utility plant additions, working capital and other utility expenditures recovered in subsequent and future periods through regulated rates. The capital necessary to meet these requirements is derived primarily from internally-generated funds, which consist of cash flows from operating activities, excluding payment of dividends. The Company initially supplements internally generated funds through bank borrowings, as needed, under unsecured short-term bank lines. Periodically, the Company replaces portions of its short-term debt with long-term financings more closely matched to the long-term nature of its utility assets.

The continued availability of these methods of financing, as well as the Company’s choice of a specific form of security, will depend on many factors, including, but not limited to: security market conditions; general economic climate; regulatory approvals; the ability to meet covenant issuance restrictions, if any; the level of the Company’s earnings, cash flows and financial position; and the competitive pricing offered by financing sources.

At June 30, 2008, Unitil had $37 million in unsecured revolving lines of credit through two banks. The Company had short-term debt outstanding through bank borrowings of $12.8 million and $9.5 million at June 30, 2008 and June 30, 2007, respectively. In addition, Unitil had approximately $4.3 million in cash at June 30, 2008.

On February 15, 2008, the Company entered into a Stock Purchase Agreement with NiSource and Bay State to acquire all of the outstanding stock of Northern Utilities, Inc. and Granite State Gas Transmission, Inc. The Company has a commitment letter to enter into a senior unsecured bridge facility, which may be used to finance this transaction. The Company anticipates either financing the initial acquisition or refinancing the bridge facility with the issuance of a combination of long-term debt and common equity securities.

The Company provides limited guarantees on certain energy contracts entered into by its regulated subsidiary companies. The Company’s policy is to limit these guarantees to the duration of the contracts, which range from less than one month to two and one-half years. As of June 30, 2008, there were approximately $9.0 million of guarantees outstanding and the longest term guarantee extends through October 31, 2009.

The tables below summarize the major sources and uses of cash (in millions) for the three months ended June 30, 2008, compared to the same period in 2007.


Cash Provided by Operating Activities	$	19.8	$	17.0

Cash Provided by Operating Activities –Cash Provided by Operating Activities was $19.8 million during the six months ended June 30, 2008, an increase of $2.8 million over the comparable period in 2007. Cash flow from Net Income, adjusted for non-cash charges to depreciation, amortization and deferred taxes of $1.2 million, was $4.9 million higher in the first six months of 2008 compared to 2007. Working Capital related cash flows decreased by $0.6 million during the first six months of 2008 compared to the same period in 2007. Deferred Restructuring Charges provided $0.8 million in cash in the second quarter of 2008 compared to the same period in 2007. These charges were deferred in prior periods for collection in current rates. All other changes in operating activities were a net $2.3 million in uses of cash in the first six months of 2008 compared to 2007.


Cash (Used in) Investing Activities	$	(10.2	)	$	(19.6	)

Cash (Used in) Investing Activities – Cash (Used in) Investing Activities was $10.2 million for the six months ended June 30, 2008, a decrease in capital spending of $9.4 million over the comparable period in 2007. This is mainly due to the funding in 2007 and the completion in 2008 of the Company’s Advanced Metering Infrastructure (“AMI”) project. In the first six months of 2007, capital expenditures included approximately $5.4 million of cash outlays for investment in the AMI project. Capital expenditure projections are subject to changes during the fiscal year.


Cash Provided by (Used in) Financing Activities	$	(9.9	)	$	0.2

Cash Provided by (Used in) Financing Activities - Cash (Used in) Financing Activities was $9.9 million in the three months ended June 30, 2008, reflecting an increase in the use of cash of $10.1 million over the comparable period in 2007. In the second quarter of 2007, Unitil received cash proceeds of $20.0 million from the issuance of Senior Long-term Notes, which was used to pay down Short-term Debt. As a result, the Company utilized an additional $10.5 million in short-term debt for the first six months of 2008 compared to the same period in 2007. All other cash flows used in other financing activities aggregated to a net $0.4 million increase in the first six months of 2008 over the comparable period in 2007.

CRITICAL ACCOUNTING POLICIES

The preparation of the Company’s financial statements in conformity with generally accepted accounting principles in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. In making those estimates and assumptions, management is sometimes required to make difficult, subjective and/or complex judgments about the impact of matters that are inherently uncertain and for which different estimates that could reasonably have been used could have resulted in material differences in its financial statements. If actual results were to differ significantly from those estimates, assumptions and judgments, the financial statements of the Company could be materially different than reported. The following is a summary of the Company’s most critical accounting policies, which are defined as those policies where judgments or uncertainties could materially affect the application of those policies. For a complete discussion of the Company’s significant accounting policies, refer to the Note 1 to the Consolidated Financial Statements in the Company’s Annual Report on Form 10-K, as filed with the Securities and Exchange Commission on February 12, 2008.

Regulatory Accounting - The Company’s principal business is the distribution of electricity and natural gas by the retail distribution companies: UES and FG&E. Both UES and FG&E are subject to regulation by the FERC and FG&E is regulated by the MDPU and UES is regulated by the NHPUC. Accordingly, the Company uses the provisions of FASB Statement No. 71, “Accounting for the Effects of Certain Types of Regulation.” (SFAS No. 71). In accordance with SFAS No. 71, the Company has recorded Regulatory Assets and Regulatory Liabilities which will be recovered from customers, or applied for customer benefit, in accordance with rate provisions approved by the applicable public utility regulatory commission.

The Company’s principal regulatory assets and liabilities are detailed on the Company’s Consolidated Balance Sheet and a summary of the Company’s Regulatory Assets is provided below. The Company receives a return on investment on its regulated assets for which a cash outflow has been made.

Regulatory commissions can reach different conclusions about the recovery of costs, which can have a material impact on the Company’s consolidated financial statements. The Company believes it is probable that its regulated utility companies will recover their investments in long-lived assets, including regulatory assets. The Company also has commitments under long-term contracts for the purchase of electricity and natural gas from various suppliers. The annual costs under these contracts are included in Purchased Electricity and Purchased Gas in the Consolidated Statements of Earnings and these costs are recoverable in current and future rates under various orders issued by the FERC, MDPU and NHPUC.


Regulatory Assets consist of the following (millions)
	June 30,				December 31,
	2008		2007		2007
Power Supply Buyout Obligations	$	62.7	$	82.6	$	72.7
Deferred Restructuring Costs		28.8		30.1		30.5
Generation-related Assets		1.2		2.1		1.6

Subtotal – Restructuring Related Items		92.7		114.8		104.8

Retirement Benefit Obligations		35.1		37.2		35.1
Income Taxes		13.8		18.3		14.6
Environmental Obligations		11.3		13.1		13.1
Other		3.3		3.9		2.9

Total Regulatory Assets	$	156.2	$	187.3	$	170.5

If the Company, or a portion of its assets or operations, were to cease meeting the criteria for application of these accounting rules, accounting standards for businesses in general would become applicable and immediate recognition of any previously deferred costs, or a portion of deferred costs, would be required in the year in which the criteria are no longer met, if such deferred costs were not recoverable in the portion of the business that continues to meet the criteria for application of SFAS No. 71. If unable to continue to apply the provisions of SFAS No. 71, the Company would be required to apply the provisions of FASB Statement No. 101, “Regulated Enterprises – Accounting for the Discontinuation of Application of Financial Accounting Standards Board Statement No. 71.” In the Company’s opinion, its regulated operations will be subject to SFAS No. 71 for the foreseeable future.

Utility Revenue Recognition - Regulated utility revenues are based on rates and charges approved by federal and state regulatory commissions. Revenues related to the sale of electric and gas service are recorded when service is rendered or energy is delivered to customers. The determination of energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each calendar month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. This unbilled revenue is estimated each month based on estimated customer usage by class and applicable customer rates.

Allowance for Doubtful Accounts - The Company recognizes a Provision for Doubtful Accounts each month. The amount of the monthly Provision is based upon the Company’s experience in collecting electric and gas utility service accounts receivable in prior years. Account write-offs, net of recoveries, are processed monthly. At the end of each month, an analysis of the delinquent receivables is performed and the adequacy of the Allowance for Doubtful Accounts is reviewed. The analysis takes into account an assumption about the cash recovery of delinquent receivables and also uses calculations related to customers who have chosen payment plans to resolve their arrears. The analysis also calculates the amount of written-off receivables that are recoverable through regulatory rate reconciling mechanisms. The Company is authorized by regulators to recover the supply-related portion of its written-off accounts from customers through periodically reconciling rate mechanisms. Evaluating the adequacy of the Allowance for Doubtful Accounts requires judgment about the assumptions used in the analysis, including expected fuel assistance payments from governmental authorities and the level of customers enrolling in payment plans with the Company. Also, the Company has experienced periods when state regulators have extended the periods during which certain standard credit and collection activities of utility companies are suspended. In periods when account write-offs exceed estimated levels, the Company adjusts the Provision for Doubtful Accounts to maintain an adequate Allowance for Doubtful Accounts balance. It has been the Company’s experience that the assumptions it has used in evaluating the adequacy of the Allowance for Doubtful Accounts have proven to be reasonably accurate.

Retirement Benefit Obligations - The Company sponsors the Unitil Corporation Retirement Plan (Pension Plan), which is a defined benefit pension plan covering substantially all of its employees. The Company also sponsors an unfunded retirement plan, the Unitil Corporation Supplemental Executive Retirement Plan (SERP), covering certain executives of the Company and an employee 401(k) savings plan. Additionally, the Company

sponsors the Unitil Employee Health and Welfare Benefits Plan (PBOP Plan), primarily to provide health care and life insurance benefits to retired employees.

In September 2006, the FASB issued FASB Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”, (SFAS No. 158), an amendment of SFAS No. 87, “Employers’ Accounting for Pensions”, SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” SFAS No. 106, “Employers’ Accounting for Postretirement Benefits other than Pensions” and SFAS No. 132(R), “Employers’ Disclosures about Pensions and Other Postretirement Benefits.” SFAS No. 158 requires companies to record on their balance sheets as an asset or liability the overfunded or underfunded status of their retirement benefit obligations (RBO) based on the projected benefit obligation. The Company has recognized a corresponding Regulatory Asset, to recognize the future collection of these obligations in electric and gas retail rates.

The Company’s reported costs of providing retirement benefits are dependent upon numerous factors resulting from actual plan experience and assumptions of future experience. The Company has made critical estimates related to actuarial assumptions, including assumptions of expected returns on plan assets, future compensation, health care cost trends, and appropriate discount rates. The Company’s health care cost trend assumptions are developed based on historical cost data, the near-term outlook and an assessment of likely long-term trends. The Company’s RBO are affected by actual employee demographics, the level of contributions made to the plans, earnings on plan assets, and health care cost trends. Changes made to the provisions of these plans may also affect current and future costs. The Company’s RBO may also be significantly affected by changes in key actuarial assumptions, including, anticipated rates of return on plan assets and the discount rates used in determining the Company’s RBO.

If these assumptions were changed, the resultant change in benefit obligations, fair values of plan assets, funded status and net periodic benefit costs could have a material impact on the Company’s financial statements. The discount rate assumptions used in determining retirement plan costs and retirement plan obligations are based on a market average of long-term bonds that receive one of the two highest ratings given by a recognized rating agency. For the years ended December 31, 2007 and 2006, a change in the discount rate of 0.25% would have resulted in an increase or decrease of approximately $200,000 in the Net Periodic Benefit Cost for the Pension Plan. For the years ended December 31, 2007 and 2006, a 1.0% increase in the assumption of health care cost trend rates would have resulted in increases in the Net Periodic Benefit Cost for the PBOP Plan of $690,000 and $683,000, respectively. Similarly, a 1.0% decrease in the assumption of health care cost trend rates for those same time periods would have resulted in decreases in the Net Periodic Benefit Cost for the PBOP Plan of $539,000 and $530,000, respectively. (See Note 8)

Income Taxes - Provisions for income taxes are calculated in each of the jurisdictions in which the Company operates for each period for which a statement of income is presented. This process involves estimating the Company’s current tax liabilities as well as assessing temporary and permanent differences resulting from the timing of the deductions of expenses and recognition of taxable income for tax and book accounting purposes. These temporary differences result in deferred tax assets and liabilities, which are included in the Company’s consolidated balance sheets. The Company accounts for income tax assets, liabilities and expenses in accordance with FASB Statement No. 109, “Accounting for Income Taxes” (SFAS No. 109) and under FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), an interpretation of FAS 109.

Depreciation - Depreciation expense is calculated on a group straight-line basis based on the useful lives of assets and judgment is involved when estimating the useful lives of certain assets. The Company conducts independent depreciation studies on a periodic basis as part of the regulatory ratemaking process and considers the results presented in these studies in determining the useful lives of the Company’s fixed assets. A change in the estimated useful lives of these assets could have a material impact on the Company’s consolidated financial statements.

Commitments and Contingencies - The Company’s accounting policy is to record and/or disclose commitments and contingencies in accordance with SFAS No. 5. SFAS No. 5 applies to an existing condition, situation, or set of circumstances involving uncertainty as to possible loss that will ultimately be resolved when one or more future events occur or fail to occur. As of June 30, 2008, the Company is not aware of any material commitments or contingencies other than those disclosed in the Commitments and Contingencies footnote to the Company’s consolidated financial statements below.

Refer to “Recently Issued Accounting Pronouncements in Note 1 of the Notes of Consolidated Financial Statements for information regarding recently issued accounting standards.

LABOR RELATIONS

There are approximately 100 employees of the Company represented by labor unions. In May 2005, the Company reached agreements with its bargaining units for new five-year contracts, effective June 1, 2005. These agreements replace contracts that expired on May 31, 2005.

INTEREST RATE RISK

The majority of the Company’s debt outstanding represents long-term notes bearing fixed rates of interest. Changes in market interest rates do not affect interest expense resulting from these outstanding long-term debt securities. However, the Company periodically repays its short-term debt borrowings through the issuance of new long-term debt securities. Changes in market interest rates may affect the interest rate and corresponding interest expense on any new long-term debt securities issued by the Company. In addition, the Company’s short-term debt borrowings bear a variable rate of interest. As a result, changes in short-term interest rates will increase or decrease the Company’s interest expense in future periods. For example, if the Company had an average amount of short-term debt outstanding of $25 million for the period of one year, a change in interest rates of 1% would result in a change in annual interest expense of approximately $250,000 (pre-tax). The average interest rates on the Company’s short-term borrowings for the three months ended June 30, 2008 and June 30, 2007 were 2.84% and 5.77%, respectively. The average interest rates on the Company’s short-term borrowings for the six months ended June 30, 2008 and June 30, 2007 were 3.40% and 5.77%, respectively.

MARKET RISK

Although Unitil’s utility operating companies are subject to commodity price risk as part of their traditional operations, the current regulatory framework within which these companies operate allows for full collection of electric power and natural gas supply costs in rates on a pass-through basis. Consequently, there is limited commodity price risk after consideration of the related rate-making. Additionally, as discussed above and below in Regulatory Matters, the Company has divested its commodity-related contracts and therefore, further reduced its exposure to commodity risk.

REGULATORY MATTERS

Please refer to Note 6 to the Consolidated Financial Statements in Part I, Item 1 of this report for a discussion of Regulatory Matters.

ENVIRONMENTAL MATTERS

Please refer to Note 7 to the Consolidated Financial Statements in Part I, Item 1 of this report for a discussion of Environmental Matters.

Item 1.

Financial Statements

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF EARNINGS

(Millions except common shares and per share data)

(UNAUDITED)


	Three Months Ended June 30,				Six Months Ended June 30,
	2008		2007		2008		2007
Operating Revenues
Electric	$	52.0	$	51.7	$	108.6	$	114.4
Gas		6.6		6.4		20.9		20.6
Other		0.8		0.9		1.8		1.8

Total Operating Revenues		59.4		59.0		131.3		136.8

Operating Expenses
Purchased Electricity		36.8		36.3		79.7		84.5
Purchased Gas		3.9		3.9		12.9		13.7
Operation and Maintenance		7.0		6.8		11.7		13.3
Conservation & Load Management		0.9		1.1		1.5		2.1
Depreciation and Amortization		4.5		4.4		9.7		8.9
Provisions for Taxes:
Local Property and Other		1.4		1.4		3.1		2.9
Federal and State Income		0.7		0.8		2.5		2.4

Total Operating Expenses		55.2		54.7		121.1		127.8

Operating Income		4.2		4.3		10.2		9.0
Non-Operating Expenses		0.2		0.1		0.3		0.1

Income Before Interest Expense		4.0		4.2		9.9		8.9
Interest Expense, Net		2.3		2.4		4.9		4.5

Net Income		1.7		1.8		5.0		4.4
Less: Dividends on Preferred Stock		0.1		0.1		0.1		0.1

Earnings Applicable to Common Shareholders	$	1.6	$	1.7	$	4.9	$	4.3

Average Common Shares Outstanding – Basic (000’s)		5,736		5,642		5,728		5,634
Average Common Shares Outstanding – Diluted (000’s)		5,741		5,663		5,733		5,653
Earnings Per Common Share (Basic and Diluted)	$	0.28	$	0.30	$	0.85	$	0.76
Dividends Declared Per Share of Common Stock	$	0.345	$	0.345	$	1.035	$	1.035

(The accompanying notes are an integral part of these consolidated unaudited financial statements.)

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS

(Millions)


	(UNAUDITED) June 30,				December 31,
	2008		2007		2007
ASSETS:

Utility Plant:
Electric	$	272.8	$	259.2	$	266.2
Gas		69.8		64.6		67.8
Common		27.2		25.6		26.2
Construction Work in Progress		7.3		21.5		20.3

Total Utility Plant		377.1		370.9		380.5
Less: Accumulated Depreciation		126.0		127.1		131.6

Net Utility Plant		251.1		243.8		248.9

Current Assets:
Cash		4.3		2.2		4.6
Accounts Receivable – Net of Allowance for
Doubtful Accounts of $1.3, $2.4 and $1.3		22.5		21.7		24.9
Accrued Revenue		14.2		9.0		12.7
Refundable Taxes		—		—		0.7
Materials and Supplies		3.9		3.3		4.5
Prepayments and Other		1.6		1.8		1.5

Total Current Assets		46.5		38.0		48.9

Noncurrent Assets:
Regulatory Assets		156.2		187.3		170.5
Debt Issuance Costs, net		2.7		2.8		2.8
Other Noncurrent Assets		7.1		1.9		3.5

Total Noncurrent Assets		166.0		192.0		176.8

TOTAL	$	463.6	$	473.8	$	474.6

(The accompanying notes are an integral part of these consolidated unaudited financial statements.)

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED BALANCE SHEETS (Cont.)

(Millions)


	(UNAUDITED) June 30,				December 31,
	2008		2007		2007
CAPITALIZATION AND LIABILITIES:

Capitalization:
Common Stock Equity	$	100.0	$	96.9	$	100.4
Preferred Stock, Non-Redeemable, Non-Cumulative		0.2		0.2		0.2
Preferred Stock, Redeemable, Cumulative		1.8		1.8		1.9
Long-Term Debt, Less Current Portion		159.4		160.0		159.6

Total Capitalization		261.4		258.9		262.1

Current Liabilities:
Long-Term Debt, Current Portion		0.4		0.3		0.4
Capitalized Leases, Current Portion		0.2		0.3		0.3
Short-Term Debt		12.8		9.5		18.8
Accounts Payable		18.2		15.1		17.6
Taxes Payable		0.1		2.4		—
Interest and Dividends Payable		3.9		3.8		1.9
Other Current Liabilities		4.6		4.1		5.1

Total Current Liabilities		40.2		35.5		44.1

Deferred Income Taxes		34.2		31.9		33.4

Noncurrent Liabilities:
Power Supply Contract Obligations		62.7		82.6		72.7
Retirement Benefit Obligations		51.0		51.3		48.2
Environmental Obligations		12.0		12.0		12.0
Capitalized Leases, Less Current Portion		0.4		0.5		0.5
Other Noncurrent Liabilities		1.7		1.1		1.6

Total Noncurrent Liabilities		127.8		147.5		135.0

TOTAL	$	463.6	$	473.8	$	474.6

(The accompanying notes are an integral part of these consolidated unaudited financial statements.)

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Millions)

(UNAUDITED)


	Six Months Ended June 30,
	2008			2007
Operating Activities:
Net Income	$	5.0		$	4.4
Adjustments to Reconcile Net Income to Cash Provided by Operating Activities:
Depreciation and Amortization		9.7			8.9
Deferred Taxes		1.2			(2.3	)
Changes in Current Assets and Liabilities:
Accounts Receivable		2.4			0.8
Accrued Revenue		(1.5	)		4.8
Accounts Payable		0.6			(4.7	)
Taxes Payable		0.8			1.5
All other Current Assets and Liabilities		—			0.5
Deferred Restructuring Charges		1.7			0.9
Other, net		(0.1	)		2.2

Cash Provided by Operating Activities		19.8			17.0


Investing Activities:
Property, Plant and Equipment Additions		(10.2	)		(19.6	)

Cash (Used in) Investing Activities		(10.2	)		(19.6	)


Financing Activities:
Proceeds From (Repayment of) Short-Term Debt, net		(6.0	)		(16.5	)
Proceeds From (Repayment of) Long-Term Debt		(0.2	)		20.0
Dividends Paid		(4.0	)		(4.0	)
Issuance of Common Stock		0.5			0.5
Retirement of Preferred Stock		—			(0.1	)
Other, net		(0.2	)		0.3

Cash (Used in) Provided by Financing Activities		(9.9	)		0.2

Net (Decrease) in Cash		(0.3	)		(2.4	)
Cash at Beginning of Period		4.6			4.6

Cash at End of Period	$	4.3		$	2.2


Supplemental Cash Flow Information:
Interest Paid	$	6.1		$	5.7
Income Taxes Paid	$	0.5		$	3.3

(The accompanying notes are an integral part of these consolidated unaudited financial statements.)

UNITIL CORPORATION AND SUBSIDIARY COMPANIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation – The accompanying unaudited consolidated financial statements of Unitil have been prepared in accordance with the instructions to Form 10-Q and include all of the information and footnotes required by generally accepted accounting principles. In the opinion of management, all adjustments considered necessary for a fair presentation have been included. The results of operations for the three and six months ended June 30, 2008 are not necessarily indicative of results to be expected for the year ending December 31, 2008. For further information, please refer to Note 1 of Part II to the Consolidated Financial Statements – “Summary of Significant Accounting Policies” of the Company’s Form 10-K for the year ended December 31, 2007, as filed with the SEC on February 12, 2008, for a description of the Company’s Basis of Presentation.

Nature of Operations – Unitil Corporation (Unitil or the Company) is a public utility holding company. Unitil and its subsidiaries are subject to regulation as a holding company system by the Federal Energy Regulatory Commission (FERC) under the Energy Policy Act of 2005. Prior to the passage of the Energy Policy Act of 2005, Unitil and its subsidiaries were subject to regulation as a registered holding company system under the Public Utility Holding Company Act of 1935 (PUHCA) by the Securities and Exchange Commission (SEC). As a result of the enactment of the Energy Policy Act of 2005, PUHCA has been repealed. The following companies are wholly-owned subsidiaries of Unitil: Unitil Energy Systems, Inc. (UES), Fitchburg Gas and Electric Light Company (FG&E), Unitil Power Corp. (Unitil Power), Unitil Realty Corp. (Unitil Realty), Unitil Service Corp. (Unitil Service) and its non-regulated business unit Unitil Resources, Inc. (Unitil Resources). Usource, Inc. and Usource L.L.C. are subsidiaries of Unitil Resources.

Unitil’s principal business is the retail distribution of electricity in the southeastern seacoast and capital city areas of New Hampshire and the retail distribution of both electricity and natural gas in the greater Fitchburg area of north central Massachusetts, through the Company’s two wholly-owned subsidiaries, UES and FG&E, collectively referred to as the retail distribution utilities.

A third utility subsidiary, Unitil Power, formerly functioned as the full requirements wholesale power supply provider for UES. In connection with the implementation of electric industry restructuring in New Hampshire, Unitil Power ceased being the wholesale supplier of UES on May 1, 2003 and divested of its long-term power supply contracts through the sale of the entitlements to the electricity associated with various electric power supply contracts it had acquired to serve UES’ customers.

Unitil also has three other wholly-owned subsidiaries: Unitil Service, Unitil Realty and Unitil Resources. Unitil Service provides, at cost, a variety of administrative and professional services, including regulatory, financial, accounting, human resources, engineering, operations, technology and management services on a centralized basis to its affiliated Unitil companies. Unitil Realty owns and manages the Company’s corporate office in Hampton, New Hampshire and leases this facility to Unitil Service under a long-term lease arrangement. Unitil Resources is the Company’s wholly-owned non-regulated subsidiary. Usource, Inc. and Usource L.L.C. (collectively, Usource) are wholly-owned subsidiaries of Unitil Resources. Usource provides brokering and advisory services to large commercial and industrial customers in the northeastern United States.

Recently Issued Pronouncements – In May 2008, the FASB issued FASB Statement No. 162, “The Hierarchy of Generally Accepted Accounting Principles”, (SFAS No. 162), effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board’s amendments to AU Section 411. SFAS No. 162 identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles in the United States. The Company will adopt SFAS No. 162 when it is approved and does not expect it to have any impact on its financial statements.

In March 2008, the FASB issued FASB Statement No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133” (SFAS No. 161), effective for fiscal years and interim periods beginning after November 15, 2008, with early adoption allowed. SFAS No. 161 amends and expands the disclosure requirements of SFAS No. 133 with the intent to provide users of financial statements with an enhanced understanding of an entity’s use of derivative instruments and the effect of those derivative instruments on an entity’s financial statements. The Company adopted SFAS No. 161 and there was no impact on its financial statements.

In December 2007, the FASB issued FASB Statement No. 141 (Revised 2007), “Business Combinations” (SFAS No. 141R), effective prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. SFAS No. 141R establishes principles and requirements on how an acquirer recognizes and measures in its financial statements identifiable assets acquired, liabilities assumed, noncontrolling interests in the acquiree, goodwill or gain from a bargain purchase and accounting for transaction costs. Additionally, SFAS No. 141R determines what information must be disclosed to enable users of the financial statements to evaluate the nature and financial effects of the business combination. The Company will adopt SFAS No. 141R upon its effective date and expects the adoption to affect any business combinations effected on or subsequent to that date.

In September 2006, the FASB issued FASB Statement No. 157, “Fair Value Measurements”, (SFAS No. 157). SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. Certain requirements of SFAS No. 157 are effective for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The effective date for other requirements of SFAS No. 157 has been deferred for one year by the FASB. The Company adopted the sections of SFAS No. 157 which are effective for fiscal years beginning after November 15, 2007 and there was no additional impact on the Company’s Consolidated Financial Statements. The Company’s fixed rate long-term debt falls under the fair value reporting requirements of SFAS No. 157. Accordingly, the Company has estimated the fair value of its long-term debt as of June 30, 2008 based on the quoted market prices for the same or similar issues, or on the current rates offered to the Company for debt of the same remaining maturities (See Note 4). The Company does not expect that the adoption of the deferred sections of SFAS No. 157 will have an impact on the Company’s Consolidated Financial Statements.

NOTE 2 – DIVIDENDS DECLARED PER SHARE


Declaration Date	Date Paid (Payable)	Shareholder of Record Date	Dividend Amount
06/19/08	08/15/08	08/01/08	$0.345
03/20/08	05/15/08	05/01/08	$ 0.345
01/17/08	02/15/08	02/01/08	$ 0.345
09/13/07	11/15/07	11/01/07	$ 0.345
06/21/07	08/15/07	08/01/07	$ 0.345
03/22/07	05/15/07	05/01/07	$ 0.345
01/18/07	02/15/07	02/01/07	$ 0.345

NOTE 3 – COMMON STOCK AND PREFERRED STOCK

During the first six months of 2008, the Company sold 14,889 shares of its Common Stock, at an average price of $27.76 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan and its 401(k) plans. Net proceeds of approximately $413,000 were used to reduce short-term borrowings.

During the first six months of 2007, the Company sold 19,199 shares of its Common Stock, at an average price of $26.59 per share, in connection with its Dividend Reinvestment and Stock Purchase Plan and its 401(k) plans. Net proceeds of approximately $511,000 were used to reduce short-term borrowings.

Also, in the second quarter of 2008, the Company issued and sold 3,000 shares of its Common Stock, at an average price of $24.63 per share, in connection with the exercise of stock options under the Unitil Corporation 1998 Stock Option Plan (1998 Plan). Net proceeds of $73,875 were used by the Company to reduce short-term borrowings. As disclosed in Note 2 to the Company’s Form 10-K for the year ended December 31, 2007, the 1998 Plan became effective on December 11, 1998. The number of shares granted under this plan, as well as the terms and conditions of each grant, were determined by the Compensation Committee of the Board of Directors, subject to plan limitations. All options granted under this plan vested over a three-year period from the date of the grant, with 25% vesting on the first anniversary of the grant, 25% vesting on the second anniversary, and 50% vesting on the third anniversary. Under the terms of this plan, key employees may be granted options to purchase the Company’s Common Stock at no less than 100% of the market price on the date the option is granted. All options must be exercised no later than 10 years after the date on which they were granted. This plan was terminated on January 16, 2003. There was no compensation expense associated with this plan in 2008 and 2007. The plan will remain in effect solely for the purposes of the continued administration of all options currently outstanding under the plan. No further grants of options will be made under this plan. As of June 30, 2008, there are 104,000 options vested and exercisable outstanding.

The Company maintains a Restricted Stock Plan (the Plan) which has been ratified and approved by the Company’s shareholders. On February 6, 2008, 15,540 restricted shares were issued in conjunction with the Plan with an aggregate market value at the date of issuance of $445,998. Compensation expense associated with shares issued under the Plan is recognized ratably as the shares vest and was $0.2 million and $0.2 million for six months ended June 30, 2008 and 2007, respectively. At June 30, 2008, there was approximately $1.0 million of total unrecognized compensation cost related to non-vested shares under the Plan which is expected to be recognized over approximately 2.8 years as the shares vest.

Details on preferred stock at June 30, 2008, June 30, 2007 and December 31, 2007 are shown below:

(Amounts in Millions)


	(Unaudited) June 30,				December 31,
	2008		2007		2007
Preferred Stock
UES Preferred Stock, Non-Redeemable, Non-Cumulative:
6.00% Series, $100 Par Value	$	0.2	$	0.2	$	0.2
FG&E Preferred Stock, Redeemable, Cumulative:
5.125% Series, $100 Par Value		0.8		0.8		0.9
8.00% Series, $100 Par Value		1.0		1.0		1.0

Total Preferred Stock	$	2.0	$	2.0	$	2.1

NOTE 4 – LONG-TERM DEBT

Details on long-term debt at June 30, 2008, June 30, 2007 and December 31, 2007 are shown below:

(Amounts in Millions)


	(Unaudited) June 30,				December 31,
	2008		2007		2007
Unitil Corporation Senior Notes:
6.33% Notes, Due May 1, 2022	$	20.0	$	20.0	$	20.0

Unitil Energy Systems, Inc.:
First Mortgage Bonds:
8.49% Series, Due October 14, 2024		15.0		15.0		15.0
6.96% Series, Due September 1, 2028		20.0		20.0		20.0
8.00% Series, Due May 1, 2031		15.0		15.0		15.0
6.32% Series, Due September 15, 2036		15.0		15.0		15.0

Fitchburg Gas and Electric Light Company:
Long-Term Notes:
6.75% Notes, Due November 30, 2023		19.0		19.0		19.0
7.37% Notes, Due January 15, 2029		12.0		12.0		12.0
7.98% Notes, Due June 1, 2031		14.0		14.0		14.0
6.79% Notes, Due October 15, 2025		10.0		10.0		10.0
5.90% Notes, Due December 15, 2030		15.0		15.0		15.0

Unitil Realty Corp.:
Senior Secured Notes:
8.00% Notes, Due August 1, 2017		4.8		5.3		5.0

Total Long-Term Debt		159.8		160.3		160.0
Less: Current Portion		0.4		0.3		0.4

Total Long-term Debt, Less Current Portion	$	159.4	$	160.0	$	159.6

The fair value of the Company’s long-term debt is estimated based on the quoted market prices for the same or similar issues, or on the current rates offered to the Company for debt of the same remaining maturities. The fair value of the Company’s long-term debt at June 30, 2008 is estimated to be approximately $162 million, before considering any costs, including prepayment costs, to market the Company’s debt. Currently, the Company believes that there is no active market in the Company’s debt securities, which have all been sold through private placements.

The Company provides limited guarantees on certain energy contracts entered into by its regulated subsidiary companies. The Company’s policy is to limit these guarantees to two years or less. As of June 30, 2008 there are $9 million of guarantees outstanding and these guarantees extend through October 31, 2009. These guarantees are not required to be recorded under the provisions of FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.”

NOTE 5 – SEGMENT INFORMATION

The following table provides significant segment financial data for the three and six months ended June 30, 2008 and June 30, 2007 (Millions):


Three Months Ended:	Electric		Gas			Other			Non- Regulated		Total

June 30, 2008
Revenues	$	52.0	$	6.6		$	—		$	0.8	$	59.4
Segment Profit (Loss)		2.0		(0.3	)		(0.1	)		—		1.6
Capital Expenditures		5.4		0.2			0.1			—		5.7

June 30, 2007
Revenues	$	51.7	$	6.4		$	—		$	0.9	$	59.0
Segment Profit (Loss)		2.0		(0.4	)		—			0.1		1.7
Capital Expenditures		8.0		1.5			0.5			—		10.0

Six Months Ended:

June 30, 2008
Revenues	$	108.6	$	20.9		$	—		$	1.8	$	131.3
Segment Profit (Loss)		2.5		2.5			(0.2	)		0.1		4.9
Capital Expenditures		9.6		0.5			0.1			—		10.2
Segment Assets		326.2		108.5			27.9			1.0		463.6

June 30, 2007
Revenues	$	114.4	$	20.6		$	—		$	1.8	$	136.8
Segment Profit (Loss)		3.4		0.7			0.1			0.1		4.3
Capital Expenditures		17.1		2.2			0.3			—		19.6
Segment Assets		339.5		110.6			22.6			1.1		473.8

NOTE 6 – REGULATORY MATTERS

UNITIL’S REGULATORY MATTERS ARE DESCRIBED IN NOTE 5 TO THE FINANCIAL STATEMENTS IN ITEM 8 OF PART II OF UNITIL CORPORATION’S FORM 10-K FOR DECEMBER 31, 2007 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON FEBRUARY 12, 2008.

FG&E – Electric Division – On December 3, 2007, FG&E submitted its annual reconciliation of costs and revenues for Transition, Transmission, Standard Offer Service, and Default Service filed under its restructuring plan (the Annual Reconciliation Filing). The rates were approved effective January 1, 2008, subject to reconciliation pursuant to the MDPU’s investigation. On June 6, 2008, FG&E submitted a revised Transition Charge reducing the recovery of net costs associated with the sale of Wyman 4 by $36,762 pursuant to an agreement with the Attorney General. This matter remains pending before the MDPU.

FG&E – Other – On June 22, 2007, the MDPU opened an inquiry into revenue decoupling for gas and electric distribution utilities, generally defined as a ratemaking mechanism designed to eliminate or reduce the dependence of a utility’s distribution revenues on sales. Revenue decoupling is intended to remove the disincentive a utility has to administer and promote customer efforts to reduce energy consumption and demand or to install distributed generation to displace electricity delivered by the utility. On July 16, 2008, the MDPU issued an order establishing a comprehensive plan for decoupling to be adopted by gas and electric distribution

utilities on a going-forward basis. Company specific rate cases will be required. Lost base revenue recovery associated with incremental energy efficiency savings will be allowed through 2012 consistent with the MDPU’s expectation that, with limited exceptions, distribution companies will be operating under decoupling plans by year-end 2012. Within 45 days of this order, each distribution company must notify the MDPU of when the company expects to file a rate case to implement decoupling.

On July 2, 2008, Massachusetts Senate Bill No. 2768 (the “Green Communities Act”) was signed into law. The Green Communities Act is intended to increase energy efficiency, update the renewable energy portfolio standard, increase public oversight of utilities, increase service quality of power companies, assist low-income energy customers, and increase the use of renewable generation and energy efficiency products. The Act requires electric companies to boost investment in energy efficiency measures that reduce energy demand and deliver savings to customers; provides a new funding source for efficiency measures through the auction of pollution allowances by power plants through the Regional Greenhouse Gas Initiative; creates stronger incentives for the development of renewable energy, like wind and solar, by requiring 15 percent of electricity to be supplied by new green power facilities by 2020 and establishing a pilot program for utilities to enter into long-term contracts with renewable energy projects; expressly authorizes cities and towns to own renewable energy facilities; and encourages green building design through updated codes, training and assistance. The MDPU is expected to initiate regulatory proceedings to implement various sections of the Act. The impact of any new measures to be required of FG&E in compliance with the Act cannot be estimated at this time.

UES –In July, 2008, the State of New Hampshire passed a law that allows electric utilities to make investments in distributed energy resources including energy efficiency and demand reduction technologies as well as clean cogeneration and renewable generation. In June, 2008, The State of New Hampshire also passed a law approving state participation in the Regional Greenhouse Gas Initiative (“RGGI”). The RGGI program begins in 2009 and requires large electric generators in the 10-state northeast region to purchase allowances for their carbon emissions. These allowances are being sold through a regional auction process and the funds will be used by the states for investments in energy efficiency and alternative energy.

On March 14, 2008, UES made its annual reconciliation and rate filing with the NHPUC under its restructuring plan, for rates effective May 1, 2008, including reconciliation of prior year costs and revenues, power supply and power supply-related stranded costs. The filing was approved on April 23, 2008. On July 9, 2008, UES proposed an increase to its External Delivery Charge, effective September 1, 2008, reflecting higher transmission costs.

On June 22, 2007, the NHPUC issued an order in its investigation into implementation of the federal Energy Policy Act of 2005 regarding the adoption of standards for time-based metering and interconnection. On August 31, 2007, the NHPUC issued an order on motion for rehearing, staying the June 22, 2007 order pending hearing and reconsideration of the issues. An order following rehearing was issued on January 22, 2008 finding that it is appropriate to implement some form of time-based metering standards and ordering that the details, including cost-benefit analyses, form of rate design, time of implementation and applicable customer classes shall be determined in separate proceedings to be initiated by the Commission.

On May 14, 2007, the NHPUC issued an order opening an investigation into the merits of instituting appropriate rate mechanisms, such as revenue decoupling, which would have the effect of removing obstacles to, and encouraging investment in, energy efficiency. This matter remains pending before the NHPUC.

Acquisition of Northern Utilities Inc. and Granite State Gas Transmission, Inc. – On February 15, 2008, the Company entered into a Stock Purchase Agreement (Agreement) with NiSource Inc. (NiSource) and Bay Sate Gas Company (Bay State, which is a wholly owned utility subsidiary of NiSource), to acquire all of the outstanding stock of Northern Utilities, Inc. (Northern), and Granite State Gas Transmission, Inc. (Granite) for $160 million in cash, which amount is subject to a working capital adjustment. The transaction is expected to be financed by newly issued common stock and debt. The Company has a commitment letter to enter into a senior unsecured bridge facility, which may be used to finance this transaction on an interim basis until permanent financing is completed.

On March 31, 2008, Unitil filed joint petitions with Nisource and BaySate along with supporting testimony with the Maine Public Utilities Commission and the New Hampshire Public Utilities Commission requesting approval of the acquisitions. The requests for approval are under active consideration and remain pending. As of June 30, 2008, the Company has deferred $3.4 million of transaction costs associated with the acquisition. The transaction

is expected to close by the fourth quarter of 2008, subject to approval by the state commissions and review by certain federal agencies.

NOTE 7 – ENVIRONMENTAL MATTERS

UNITIL’S ENVIRONMENTAL MATTERS ARE DESCRIBED IN NOTE 5 TO THE FINANCIAL STATEMENTS IN ITEM 8 OF PART II OF UNITIL CORPORATION’S FORM 10-K FOR DECEMBER 31, 2007 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON FEBRUARY 12, 2008.

The Company’s past and present operations include activities that are generally subject to extensive federal and state environmental laws and regulations. The Company believes it is in compliance with all applicable environmental and safety laws and regulations, and the Company believes that as of June 30, 2008, there are no material losses reasonably possible in excess of recorded amounts. However, there can be no assurance that significant costs and liabilities will not be incurred in the future. It is possible that other developments, such as increasingly stringent federal, state or local environmental laws and regulations could result in increased environmental compliance costs.

Included on the Company’s Consolidated Balance Sheet at June 30, 2008, in Environmental Obligations is $12.0 million related to estimated future clean up costs for permanent remediation of a former manufactured gas plant site at Sawyer Passway, located in Fitchburg, Massachusetts. A corresponding regulatory asset was recorded to reflect the future rate recovery of these costs. As noted above, please refer to Note 5 to the financial statements in Item 8 of Part II of the Company’s Form 10-K for December 31, 2007 for additional information. The Company received an insurance settlement during the first quarter of 2008 associated with environmental remediation costs. Any recovery that FG&E receives from insurance or third parties with respect to environmental response costs, net of the unrecovered costs associated therewith, are split equally between FG&E and its gas customers.

NOTE 8: RETIREMENT BENEFIT OBLIGATIONS

The Company sponsors the following retirement benefit plans to provide certain pension and postretirement benefits for its retirees and current employees as follows:

•

The Unitil Corporation Retirement Plan (Pension Plan) – The Pension Plan is a defined benefit pension plan covering substantially all of its employees. Under the Pension Plan, retirement benefits are based upon an employee’s level of compensation and length of service.

•

The Unitil Retiree Health and Welfare Benefits Plan (PBOP Plan) – The PBOP Plan provides health care and life insurance benefits to retirees. The Company has established Voluntary Employee Benefit Trusts (VEBT), into which it funds contributions to the PBOP Plan.

•

The Unitil Corporation Supplemental Executive Retirement Plan (SERP) – The SERP is an unfunded retirement plan, with participation limited to executives selected by the Board of Directors.

The following table includes the key weighted average assumptions used in determining the Company’s benefit plan costs and obligations:


	2008		2007
Used to Determine Plan Costs
Discount Rate	6.00	%	5.50	%
Rate of Compensation Increase	3.50	%	3.50	%
Expected Long-term rate of return on plan assets	8.50	%	8.50	%
Health Care Cost Trend Rate Assumed for Next Year	8.50	%	9.00	%
Ultimate Health Care Cost Trend Rate	4.00	%	4.00	%
Year that Ultimate Health Care Cost Trend Rate is reached	2017		2016

	2008		2007
Used to Determine Benefit Obligations:
Discount Rate	6.00	%	5.50	%
Rate of Compensation Increase	3.50	%	3.50	%
Health Care Cost Trend Rate Assumed for Next Year	8.50	%	8.50	%
Ultimate Health Care Cost Trend Rate	4.00	%	4.00	%
Year that Ultimate Health care Cost Trend Rate is reached	2017		2016

The following table provides the components of the Company’s Retirement plan costs ($000’s):


	Pension Plan						PBOP Plan						SERP
Three Months Ended June 30,	2008			2007			2008			2007			2008		2007
Service Cost	$	488		$	492		$	355		$	358		$	37	$	41
Interest Cost		943			834			559			514			31		29
Expected Return on Plan Assets		(1,094	)		(1,050	)		(82	)		(61	)		—		—
Prior Service Cost Amortization		27			27			341			340			—		—
Transition Obligation Amortization		—			—			6			5			—		—
Actuarial Loss Amortization		319			336			—			17			6		11

Sub-total		683			639			1,179			1,173			74		81
Amounts Capitalized and Deferred		(246	)		(219	)		(513	)		(504	)		—		—

Net Periodic Benefit Cost Recognized	$	437		$	420		$	666		$	669		$	74	$	81


	Pension Plan						PBOP Plan						SERP
Six Months Ended June 30,	2008			2007			2008			2007			2008		2007
Service Cost	$	976		$	984		$	710		$	715		$	74	$	82
Interest Cost		1,887			1,669			1,118			1,028			63		59
Expected Return on Plan Assets		(2,187	)		(2,097	)		(163	)		(122	)		—		—
Prior Service Cost Amortization		54			53			681			679			—		(1	)
Transition Obligation Amortization		—			—			11			11			—		—
Actuarial Loss Amortization		638			672			—			35			12		22

Sub-total		1,368			1,281			2,357			2,346			149		162
Amounts Capitalized and Deferred		(447	)		(436	)		(952	)		(1,017	)		—		—

Net Periodic Benefit Cost Recognized	$	921		$	845		$	1,405		$	1,329		$	149	$	162

Employer Contributions

On August 17, 2006, the Pension Protection Act of 006 (PPA) was signed into law. Included in the PPA are new minimum funding rules which will go into effect for plan years beginning in 2008. The funding target will be 100% of a plan’s liability with any shortfall amortized over seven years, with lower (92% - 100%) funding targets available to well-funded plans during the transition period. The Company expects to contribute approximately $2.8 million to fund its Pension Plan in 2008.

As of June 30, 2008, the Company had made $1.0 million and $33,000 of contributions to the PBOP and SERP Plans, respectively, in 2008. The Company presently anticipates contributing an additional $1.5 million and $26,000 to the PBOP and SERP Plans, respectively, in 2008.

NOTE 9: INCOME TAXES

The Company bills its customers sales tax in Massachusetts and consumption tax in New Hampshire. These taxes are remitted to the appropriate departments of revenue in each state and are excluded from revenues on the Company’s Consolidated Statements of Earnings.

The Company evaluated its tax positions at December 31, 2007, and at each interim reporting date in the period ended June 30, 2008 in accordance with FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (FIN 48), an interpretation of FAS 109, and has concluded that no adjustment for recognition, derecognition, settlement and foreseeable future events to any unrecognized tax liabilities or assets as defined by FIN 48 is required. The Company does not have any unrecognized tax positions for which it is reasonably possible that the total amounts recognized will significantly change within the next 12 months. The Company remains subject to examination by Federal, Massachusetts and New Hampshire tax authorities for the tax periods ended December 31, 2004; December 31, 2005; and December 31, 2006. Income tax filings for the year ended December 31, 2007 have been extended and are due September 15, 2008. The Company classifies penalty and interest expense related to income tax liabilities as an income tax expense. There are no interest and penalties recognized in the statement of earnings or accrued on the balance sheets.

NOTE 10: SUBSEQUENT EVENT – DEFINITIVE PROXY STATEMENT

On July 29, 2008, the Company filed a Definitive Proxy Statement (Proxy) with the SEC and subsequently mailed the Proxy to the Company’s shareholders. The Proxy served as notification that a special meeting of the Company’s shareholders will be held at the office of the Company on September 10, 2008 to approve and adopt an amendment to the Company’s Articles of Incorporation, as amended, to increase the authorized number of shares of common stock, no par value per share, of the Company from 8,000,000 shares to 16,000,000 shares in the aggregate and to act on such other matters that may come before the meeting and any adjournments.

The Company intends to sell and issue up to 4,000,000 shares of Common Stock in a public offering to partially finance the proposed acquisition by the Company of Northern Utilities, Inc. and Granite State Gas Transmission, Inc., as discussed above in Note 6.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

Reference is made to the “Interest Rate Risk” and “Market Risk” sections of Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (above).

Item 4.

Controls and Procedures

As of the end of the quarter covered by this Form 10-Q, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934, as amended. Based upon that evaluation, the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer concluded that the Company’s disclosure controls and procedures are effective in timely alerting them to material information relating to the Company required to be included in the Company’s periodic SEC filings.

There have been no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934) during the fiscal quarter covered by this Form 10-Q that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II. OTHER INFORMATION

Item 1.

Legal Proceedings

The Company is involved in legal and administrative proceedings and claims of various types, which arise in the ordinary course of business. Certain specific matters are discussed in Notes 6 and 7 to the Unaudited Consolidated Financial Statements. In the opinion of Management, based upon information furnished by counsel and others, the ultimate resolution of these claims will not have a material impact on the Company’s financial position.

Item 1A.

Risk Factors

There have been no material changes to the risk factors disclosed in the Company’s Form 10-K for the year-ended December 31, 2007 as filed with the Securities and Exchange Commission on February 12, 2008, other than the risks associated with the Company’s recently announced acquisition of Northern and Granite, as discussed in the Cautionary Statement section of Part I, Item 2 of this Quarterly Report on Form 10-Q for the quarter ended June 30, 2008.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

There were no sales of unregistered equity securities by the Company for the fiscal period ended June 30, 2008.

Pursuant to the written trading plan under Rule 10b5-1 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), adopted by the Company on March 20, 2008, the Company periodically repurchases shares of its Common Stock on the open market related to Employee Length of Service Awards and the stock portion of the Directors’ annual retainer. The Company may suspend or terminate its Rule 10b5-1 trading plan at any time, so long as the suspension or termination is made in good faith and not as part of a plan or scheme to evade the

prohibitions of Rule 10b-5 under the Exchange Act, or other applicable securities laws. There is no pool or maximum number of shares related to these purchases. Company repurchases are shown in the table below for the monthly periods noted:


Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
4/1/08 – 4/30/08	—		—	—	n/a
5/1/08 – 5/31/08	396	$	27.68	396	n/a
6/1/08 – 6/30/08	—		—	—	n/a

Total	396	$	27.68	396	n/a

Item 6.

Exhibits

(a) Exhibits


Exhibit No.	Description of Exhibit	Reference
11	Computation in Support of Earnings Per Average Common Share	Filed herewith

31.1	Certification of Chief Executive Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith

31.2	Certification of Chief Financial Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith

31.3	Certification of Chief Accounting Officer Pursuant to Rule 13a-14 of the Exchange Act, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002	Filed herewith

32.1	Certifications of Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002	Filed herewith

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


		UNITIL CORPORATION
		(Registrant)

Date: August 7, 2008		/s/ Mark H. Collin
		Mark H. Collin
		Chief Financial Officer

Date: August 7, 2008		/s/ Laurence M. Brock
		Laurence M. Brock
		Chief Accounting Officer